This invention relates to the recovery of materials from well bores, and more specifically from cased well bores. Sometimes such operations are referred to as “fishing.”
In the oil and gas exploration and production industry, well bores are drilled and then cased with metal pipes, generally called “casing” or “liners,” that are cemented into the ground. In this document, the term “casing” shall include “liner,” and a “cased” well shall include a “lined” well. An additional string of smaller diameter pipes, called a completion string, are installed inside of the casing strings for the function of safely transporting fluids to or from the geological zone of interest or formation. One of the principle functions of a completion string, or tubing, is to isolate the inner casing string(s) from formation pressure and formation fluids. The tubing typically establishes fluid flow with the formation through perforations created in the section of casing or liner below a production packer that seals around the lower end on the completion string. The perforation holes are usually “shot” through the casing or liner such that they penetrate the geologic zone of interest for hydrocarbons to flow into the cased hole below the packer and into the tubing string. Pumps or other equipment may be placed in the cased hole at various times, for isolation of different production zones, rework of the well, and for other operations. During any of those operations, a break in the tubing string hanging in the cased hole can cause a large amount of equipment to drop, and that equipment needs to be “fished” out of the hole.
In modern wells, more and more of the completion string equipment in the hole is controlled or monitored from the surface with control and or monitoring lines. Whether hydraulic, electric, fiber optic, chemical injection, or something else, when a component of a completion string (usually metal) that is supporting the string weight breaks and a portion or the entire string falls, the control/monitoring lines break, also.
An example is seen in FIG. 1 (not to scale). There, a subsea well head 110 (“Christmas tree” not shown) is seen mounted to sea-floor 112 under water 114. In the illustrated example, a tubing hanger 116 is mounted in wellhead 110. Also shown are vent sub 118, chemical injection sub 120, and SCSSV 122 (standing for Surface Controlled Subsurface Safety Valve). The above reside on a 5½ inch tubing 124 that connects to 7 inch tubing 126 and eventually to 6⅝ inch tubing 128. The components in FIG. 1 are highly compressed (vertically) as illustrated; those of skill in the art will recognize that, in reality, cross-over connections and different spacing than seen in FIG. 1 exist in the field.
Referring still to FIG. 1, asphaltene injection sub 130, DHP&TG (standing for Down Hole Pressure and Temperature Gauge) 132, and DHP&TG 134, are connected below on 5½ inch tubing 136 and are interconnected with 6⅝ inch tubing 128 and packer 140 (as is understood by those of skill in the art).
The completion string described above resides inside an 11¾ inch casing 142 secured by means that are not shown (but understood by those of ordinary skill) to wellhead 116 and seafloor 112. Casing 142 is connected by cross-over 144 to 9⅞ inch casing 146. Annulus 148 includes fluids that will occur to those of skill in the art.
Referring now to FIG. 2, the area showing sub 118, sub 120, and SCSSV 122, all of FIG. 1, has been illustrated in more detail. Also seen in FIG. 2 are various control/monitoring lines 212 that operate those devices and, in some embodiments, components below the packer 140. Although still not to scale, some of the possible relative distances between components is seen; for example, vent sub 118 includes 7 inch tubing 214 above and below. The sizes of the tubing sections and the subs or other controlled/monitored devices is not of significant importance for purposes of the present invention but are given by way of illustration to show the types of components and lines in wells related to it. No particular component or type of line is critical to the invention, nor is any combination.
Referring now to FIG. 3, the same string from FIG. 1 is seen in which a break 210 is seen in tubing 124. The control/monitoring lines are not shown.
In FIG. 4, the area shown in FIG. 2 is seen where the failure in tubing 124 has caused control/monitoring lines 212 to break.
Traditionally, in wells that do not include such lines, some form of tool is used to grasp the “fish” and it is pulled out. However, in the presence of the lines 212, the pulling causes a tangle between the lines and the casing. This interference will increase drag and the force needed to pull the equipment out of the well.
In at least some cases, the lines and the hardware used to attach them securely to the completion string have packed-off the annulus area to a degree that the fishing operation will have to be abandoned.
This causes a great many problems. For example, in some cases, an unsuccessful fishing operation means that the well bore must be abandoned—at a cost of many millions or even hundreds of millions of dollars if a replacement well is required. Even worse, while fishing operations are underway, offshore rigs are literally tied to the well bore. It takes a lot of time to shut down a well and secure a rig in the event of a hurricane. If the rig has become stuck, too long, the entire structure can be lost.
Therefore, there is a great need to improve the efficiency and the effectiveness of removal of materials from well bores.